1.) Field of the Invention
This invention relates to a downhole surge pressure reduction system for use in the oilwell industry. In a particular application, this invention relates to a system for reducing surge pressure while running a casing liner downhole, hanging the casing liner on casing, and cementing the casing liner in the borehole. Advantageously, this system, in one application, may be used in a method for reducing of surge pressure, hanging and cementing of the casing liner in a single trip downhole. The fluid bypass used in the system and method includes a replaceable breakaway seat.
2.) Description of the Related Art
For a long time, the oilwell industry has been aware of the problem created when lowering a drill string at a relatively rapid speed in drilling fluid. This rapid lowering of the drill string results in a corresponding increase or surge in the pressure generated by the drilling fluid in the annulus between the drill string and the casing, and the drill string and the exposed formation about the borehole. Of particular concern is the exposed formation.
This surge pressure has been problematic to the oilwell industry in that it has many detrimental effects. Some of these detrimental effects are 1.) loss volume of drilling fluid, which presently costs $40 to $400 a barrel depending on its mixture, that is primarily lost into the earth formation about the borehole, 2.) resultant weakening and/or fracturing of the formation when this surge pressure in the borehole exceeds the formation fracture pressure, particularly in older formations and/or permeable (e.g. sand) formations, 3.) loss of cement to the formation during the cementing of the casing finer in the borehole due to the weakened and, possibly, fractured formations resulting from the surge pressure on the formation, and 4.) differential sticling of the drill string or casing liner being run into a formation during oilwell operations, that is, when the surge pressure in the borehole is higher than the formation fracture pressure, the loss of drilling fluid to the formation allows the drill string or casing liner to be pushed against the permeable formation downhole and allows it to become stuck to the permeable formation.
This surge pressure problem has been further exasperated when running tight clearance casing liners or other apparatus in the existing casing. For example, the clearances in recent casing liner runs have been 1/2" to 1/4" in the annulus between the casing liner and casing. This reduction in the annulus area in these tight clearance casing liner runs have resulted in corresponding higher surge pressure and heightened concerns over their resulting detrimental effects.
The most common known response to these surge pressures is to decrease the running speed of the drill string or casing liner downhole to maintain the surge pressure at an acceptable level. An acceptable level would be a level at least where the drilling fluid pressure, including the surge pressure, is less than the formation fracture pressure to minimize the above detrimental effects. However, as can now be seen, any reduction of surge pressure would be beneficial as the more surge pressure is reduced, the faster the drill string or casing liner could be run. Time is money, particularly on the expensive offshore rigs, such as, those disclosed, but not limited to, in U.S. Pat. Nos. 4,130,503; 4,916,999; 5,290,128; 5,388,930; and 5,419,657, that are assigned to the assignee of the present invention and incorporated by reference herein for all purposes.
As used herein, a drill stem is the entire length of tubular pipes, composed of the kelly, the drill pipe and drill collars, that make up the drilling assembly from the surface to the bottom of the borehole. A drill string is defined herein as the columns or string of drill pipe, not including the drill collars or kelly. The drill pipe or pipe is defined herein as a heavy seamless tubing used to rotate the bit or other tools, run casing liner or other apparatus, or circulate the drilling fluid. Joints of pipe 30 ft. long are coupled together by means of tool joints. By connecting three lengths of pipes, a stand of pipe 90 ft. long is created. As used herein, casing is steel pipe placed in an oil or gas well as drilling progresses to prevent the borehole from caving during drilling and to provide means of extracting petroleum, if the well is productive. A casing liner or liner, as defined herein, is any casing whose top is located below the surface elevation. Finally, a casing liner hanger is a slip device, including, but not limited to, hydraulic and mechanical casing liner hangers, that attaches the casing liner to the casing.
Downhole tools now exist that aid in reducing surge pressure but the inventors are not aware of any tool that satisfies the need of a system and method for reducing surge pressure, allows torsional rotation of the drill pipe, can be cycled from open to close while in tension, provides full opening and allows hanging and cementing of a casing liner in a single trip downhole.
For example, U.S. Pat. No. 2,947,363, assigned on its face to Johnson Testers, Inc., proposes a fill-up valve for well strings that includes a movable sleeve in a housing. As taught by the '363 patent, after a predetermined amount of fluid has been admitted, a ball is dropped on the sleeve and pressure applied to move the sleeve downwardly to misalign the ports to a closed port position. Fingers on the sleeve are stated to interlock with teeth to stop upward movement of the sleeve. While the ball could be moved up the housing by an upward flow of pressurized fluid, the ball cannot be blown or forced downwardly through the sleeve. Therefore, this Johnson Testers' fill-up valve does not provide full opening for inner drill string work to be accomplished at a depth below the fill-up valve.
U.S. Pat. No. 3,376,935, assigned on its face to the Halliburton Company, proposes a well string that is partially filled with fluid during a portion of its descent into a well and, thereafter, selectively closed against the entry of further fluid while descent of the well string continues ('935 patent, col. 1, ins 25 to 47). As best shown in FIGS. 3 to 5 of the '935 patent, a ball seats on a ball seat to move the sleeve downwardly to a closed port position. Upon a predetermined pressure the seat deforms, as shown in FIG. 5, to allow the ball to pivot the flapper valve 17 downwardly and pass out of the housing 3 ('935 patent, col. 6, Ins 32 to 60). The flapper check valve 17 prevents flow of fluid (e.g. drilling fluid) up through the housing ('935 patent, col. 4, ins 60 to 73), whether or not the sleeve is in the open port position (FIG. 3) or the closed port position (FIGS. 2, 4 and 5). Additionally, as best shown in FIGS. 1 and 2, the inside diameter of the sleeve is less than the inside diameter of the drill string 2 or pipe interior 6, thereby creating a restriction in the string 2. While this Hamburton tool allows movement of fluids from the annulus, adjacent the ports 13 of the tool, to flow up the drill string, the surge pressure created by apparatus uses, below the tool, is not alleviated.
U.S. Pat. No. 4,893,678, assigned on its face to Tam International, proposes a multiple-set downhole tool and method of use of the tool. While confirming the oilwell industry desire for "full bore" opening in downhole equipment, the '678 patent proposes the use of a ball to move a sleeve to misalign a port in the sleeve and a passage in the housing. Additionally, while the ball can even be "blown out" (FIG. 5), the stated purpose of the apparatus in the '678 patent is to activate a tool, and more particularly, to inflate an elastomeric packer ('678 patent, col. 1, ins 20 to 25 and col. 3, in 14 to col. 4, In 42), not to reduce surge pressure while running a drill string with a casing liner packer or other apparatus downhole.
A Model "E" "Hydro-Trip Pressure Sub" No. 799-28, distributed by Baker Oil Tools, a Baker Hughes company of Houston, Tex., is installable on a string below a hydraulically actuated tool, such as a hydrostatic packer to provide a method of applying the tubing pressure required to actuate the tool. To set a hydrostatic packer, a ball is circulated through the tubing and packer to the seat in the "Hydro-Trip Pressure Sub", and sufficient tubing pressure is applied to actuate the setting mechanism in the packer. After the packer is set, a pressure increase to approximately 2,500 psi (17,23 MPa) shears screws to allow the ball seat to move down until fingers snap back into a groove. The sub then has a full opening, and the ball passes on down the tubing. U.S. Pat. No. 5,244,044, assigned on its face to Otis Engineering Corporation of Dallas, Tex., proposes a similar catcher sub using a ball to operate pressure operated well tools in the conduit above the catcher sub. However, neither the Baker or Otis tools provide for reduction of surge pressure by diverting fluid flow into the annulus between the drill pipe and casing.
Many attempts have been made to try and solve the surge pressure problem. Over a year before the filing of the present application, a Davis Type PVTS automatic fill float equipment was used when running a casing liner in an attempt to reduce surge pressure. Unlike standard no-fill float equipment, automatic fill float equipment allows drilling fluid to travel up inside the casing liner and the drill string. However, automatic fill float equipment does have its limitations. Although it reduces surge pressure, it does not allow for maximum running speeds. Additionally, if flow up an automatic fill float equipment reaches a predetermined value, such as in this case 1.6 bbl/min., the automatic fill feature is converted to no-fill. Upon conversion, with no means of reducing surge pressure, drilling fluid was lost to the formation, resulting in the eventual differential stickling of the casing liner.
Subsequent runs in the fall-winter of 1996, also failed to identify a method of successfully reducing surge pressure while running a casing liner and to provide an adequate means of cementation. For example, a No. 0758.05 sliding sleeve circulating sub or fluid bypass manufactured by TIW Corporation of Houston, Tex. (713) 729-2110 was used in combination with an open (no float) guide shoe.
The next attempt at reducing surge pressure while running a casing liner was made upon locating another bypass, the Halliburton RTTS circulating valve, distributed by Halliburton Services. The RTTS circulating valve, however, needed to touch on bottom to be moved to the closed port position, i.e. the J-slot sleeve needs to have weight relieved to allow the lug mandrel to move. The maximum casing liner weight that is permitted to be run below the Halliburton RTTS bypass is a function of the total yield strength of all the lugs in the RTTS bypass which are believed to significantly less than the rating of the drill string. However, this casing liner became plugged when set on bottom to facilitate closure of the bypass. Attempts were made to unplug the guide shoe, which resulted in the accidental setting of the hydraulic casing liner hanger Once again, a normal cement job was not possible, and a total of 180 hours of offshore rig time, and other costs were lost. A second run of the Halliburton fluid bypass, this time with multiple openings in the float shoe at the bottom end of the casing liner and with the float removed to reduce chances of plugging, was performed. While the second Halliburton fluid bypass run was successful in reducing surge pressure, reducing connection time, and resulted in a normal cementing of the casing liner, the concerns of future applications were apparent. The next scheduled casing liner run would require that the system be washed and reamed in the hole. This would require a bypass which could be subjected to rotational torque while also being in a compressive load state. While the TIW No. 0758.05 bypass can be rotated, both the TIW No. 0758.05 bypass and Halliburton RTTS bypass must be closed by setting on bottom. In other words, the TIW No. 0785.05 bypass and Halliburton RTTS bypass can not be closed while in tension.
Also, page 3071 of publication entitled "Brown Hughes, Hughes Production Tools Liner Equipment" and page 900 of Brown Oil Tools, Inc. General Catalog 1976-1977 disclose a Brown type circulating valve using setdown weight to move to a closed port position.
In particular, a system and method that allows 1.) a minimum of surge pressure to be placed on the formation, 2.) a drill string, casing liner or other downhole tools to be run with a minimum of time sitting on the slips during connections, 3.) washing and reaming with the casing liner in an unstable wellbore, 4.) normal drilling fluid path circulation achieved without risk or plugging the bottom of the drill string or casing liner by touching it on bottom, 5.) a normal cement job to be performed, and 6.) material and time savings resulting from above would be highly desired by the oilwell industry.
Furthermore, in the past there have been devices for releasing multiple balls into a downhole pipe, such as, U.S. Pat. Nos. 2,737,244; 3,039,531; 3,403,729; 4,033,408; 4,132,243; and 5,499,687. Also, in the past there have been devices for releasing a cement plug in downhole pipe, such as, disclosed on page 4947 of the TIW catalog 1974-1975; page 7922 of the TIW catalog 1982-1983; page 6106 of the TIW catalog 1986-1987 (the TIW devices on pages 7922 and 6106 states that they can provide a ball dropping sub for setting the TIW "HYDRO-HANGER" when necessary). Also, a bypass line for a cementing manifold that can be fitted with a ball dropping sub for use with a hydraulic casing liner hanger has been proposed on page 4260 of publication entitled "Lindsey Completion Systems 1986-1987 General Catalog". Also, a combination cement plug dropping head and swivel has been known, such as, disclosed on page 3070 of publication entitled "Brown Hughes, Hughes Production Tools liner Equipment" and page 902 of Brown Oil Tools, Inc. General Catalog 1976-1977.
However, a launching manifold additive to a top drive, such as a pipehandler PH-85 650/750 for a TDS manufactured by Varco, B. J. Drilling Systems, suspended from a traveling block for the above desired system for use in closing a flow port used for reducing surge pressures, hanging and cementing the casing liner in the borehole would be desirable. In particular, a launching manifold for interchangeable use with a top drive or kelly that would hold and release two balls, and a drill pipe wiper dart and that also includes a drilling fluid bypass path in order to wash and ream without disconnection from the top drive and drill string would be desirable.